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  • Moss Landing’s 1,500 Idle Modules Show Battery Risk for AI Power Outlasts Retirement

    Moss Landing’s 1,500 Idle Modules Show Battery Risk for AI Power Outlasts Retirement

    TL;DR · 30-second read

    The Short Version

    A giant battery site in Moss Landing, California, caught fire again on Friday. The owner is Vistra, a large power company. The site uses batteries to store electricity for the grid, and it already burned badly in January 2025.

    This time about 1,500 battery packs caught fire. They had been unplugged from the grid after the last fire, but they still held a charge. About 106 nearby residents were told to stay indoors.

    This matters because power companies and huge computing centers are counting on big batteries to keep the lights on. A battery that has been switched off can still catch fire.

    A fire broke out shortly after 6:15 a.m. on Friday, September 18, 2026, at Vistra’s battery storage facility in Moss Landing, California, the Salinas Californian reported. It started in the Moss 300 building, the same structure heavily damaged in the January 2025 fire. North Monterey County Fire District Chief Jess Cortez said the fire involved the roughly 1,500 battery modules left on the building’s north side. By a noon briefing there was no active flame. The site was “hot and smoldering” and expected to burn out within 24 hours, with drones checking battery temperatures.

    A shelter-in-place order covered about 106 residents within a third of a mile of the plant, and Dolan Road stayed closed near the site. Vistra temporarily shut down the natural gas plant on the same property as a precaution. No injuries were reported. Air monitors detected some fine particulate matter (PM 2.5), but none above screening levels, and no hydrogen fluoride.

    Executive Summary

    This is the second fire in about 20 months at one of the world’s best-known grid-scale battery sites. The detail that matters most is where it happened. Vistra plant manager Ron George said the modules that burned were idle and disconnected from the grid, but still energized, inside a unit Vistra has already retired and is remediating with the U.S. Environmental Protection Agency.

    For utilities and data-center developers who plan to use large batteries as “firming” capacity, meaning storage that fills gaps when solar, wind or other supply falls short, the lesson is about the full life of the asset. A battery that has left service can still hold energy and still ignite. The cleanup phase therefore carries its own safety, siting and insurance risk. Vistra also shut down the neighboring gas plant as a precaution, which shows how a battery incident can reach other generation on the same site.

    Both Vistra’s investigation into the cause of the January 2025 fire and a California Public Utilities Commission investigation are still open. A second fire has now occurred before either has reported a root cause.

    Retired Is Not the Same as Safe

    The headline fact is simple. The 1,500 modules that burned on September 18 were not delivering power to anyone. George said they were idle and disconnected from the grid but still energized. The Moss 300 unit was retired after the 2025 fire, and Vistra is working with the EPA on remediation. The modules that burned were sitting in a damaged building while that cleanup was under way.

    This is how lithium-ion storage behaves in general. Unplugging a battery from the grid stops it from trading power, but it does not remove the chemical energy stored in its cells. Until modules are discharged, removed or otherwise made safe, a damaged battery building remains a hazard. Operators usually model safety risk during commercial operation. Moss Landing shows that the period after an asset stops earning revenue can carry comparable risk, and the local community still bears it.

    That changes the math for anyone buying storage-backed power. A data-center operator or utility signing a long-term capacity contract is exposed to more than the chance that a battery fails during its service life. It is also exposed to how long a failed asset takes to wind down, and to what happens to neighboring assets while it does.

    One Fire, Two Assets Offline

    Vistra shut down the onsite natural gas plant “out of an abundance of caution.” Co-locating batteries with existing generation is attractive because it reuses grid connections, land and permits that took years to secure. Moss Landing shows the other side of that choice. An incident at the battery portion of a site can take down generation that has nothing to do with the batteries, at least temporarily.

    This correlation is directly relevant to AI infrastructure planning. Large computing campuses increasingly look for power from sites that pair several resources: gas, storage and solar. The goal is reliability through diversity. If one resource’s safety incident forces a precautionary shutdown of another, the reliability benefit of pairing them is smaller than it appears on paper. Buyers need to know how often that can happen and how long it lasts.

    Safeguards Worked, but Answers Are Still Pending

    Parts of the response went well. After the 2025 fire, the Monterey Bay Air Resources District oversaw installation of six additional air sensors. Four sit at the facility fence line, one at Elkhorn Elementary School and one at a nearby boatyard. Officials reported fine particulate readings within health standards and no hydrogen fluoride, a toxic gas that burning lithium-ion cells can release. Schools outside the shelter zone lifted their own orders the same day. No one was hurt.

    The monitoring also has limits. The air district’s Richard Stedman said the sensors are not testing for heavy metals, “although we would expect that to be in the smoke.” And the core question from 2025, why the original fire started, remains open in both Vistra’s investigation and the CPUC’s. Without a published root cause, other operators, insurers and permitting authorities cannot yet say which design, spacing or suppression changes would prevent a repeat. The industry is still waiting for that input to its siting and insurance decisions.

    Background

    Vistra Corp. is a large U.S. power producer. At Moss Landing on California’s Monterey Bay, it built one of the world’s largest battery energy storage installations next to an existing natural gas power plant, reusing the site’s grid connections. The batteries charge when power is abundant and discharge when California’s grid needs extra supply, often in the evening as solar output fades.

    In January 2025 a major fire damaged the facility’s Moss 300 building, which Vistra has since retired. After that fire, the Monterey Bay Air Resources District oversaw installation of six additional air monitoring sensors around the site and the community. Vistra and the California Public Utilities Commission are each still investigating the 2025 fire’s cause.

    Sources

    Source: Fire at Moss Landing battery facility ‘smoldering,’ officials say: Salinas Californian report on the September 18, 2026 fire at Vistra’s Moss Landing battery storage site.

  • Utilities Turn to AI for Data-Center Load, but 84% Need 1+ Year to Scale a Pilot

    Utilities Turn to AI for Data-Center Load, but 84% Need 1+ Year to Scale a Pilot

    TL;DR · 30-second read

    The Short Version

    Power companies across America are racing to keep up with the giant computer warehouses that run artificial intelligence, which use enormous amounts of electricity.

    A new survey of 134 innovation chiefs at American power companies found that most now use artificial intelligence themselves to manage that demand. The catch: 84% say turning a small trial into something used across the whole company takes more than a year, and that delay is getting longer.

    Why it matters to you: 83% of those leaders say the cost of serving these warehouses is showing up in household electricity bills.

    National Grid Partners, the venture capital and innovation arm of UK and US energy company National Grid, released its third annual Utility Innovation Survey on September 18, 2026, at the NextGrid Alliance Summit in Boston. The survey of 134 innovation leaders at U.S. utilities, collected between May 20 and July 7, 2026, found that 78% are deploying or operationalizing at least one AI application to manage interconnection demand, while 74% say AI-driven data center load growth is affecting grid reliability.

    The survey also found that 84% of organizations take more than a year to move projects from pilot to full rollout, up from 66% in 2024, and that grid reliability has overtaken net zero as a top-three priority. National Grid Partners also announced investments in two startups, Terragrit and LineVision, and noted that National Grid has joined the newly formed AI Energy Management Alliance as a founding member.

    Executive Summary

    The headline number is adoption: nearly four in five U.S. utility innovation leaders say they are putting AI to work on the flood of requests to connect new load, much of it from AI data centers. That is the industry using the technology driving its demand problem as part of the answer to it.

    The more consequential numbers sit underneath. Innovation budgets rose at 72% of respondents, yet the share needing more than a year to scale a pilot has climbed for three consecutive surveys, from 66% to 78% to 84%. Most spending (59%) goes to incremental improvements, only 16% to transformational projects, and 87% say regulatory and rate-case frameworks written before the AI demand boom limit returns on innovation.

    Taken together, the survey describes an industry that has accepted AI as a grid-planning tool but cannot yet deploy it at the pace data-center load is arriving. For data-center developers, utilities, regulators and ratepayers, the practical constraint is increasingly how fast utilities can change the way they plan, not only how much they build.

    The Constraint Is Speed, Not Willingness

    The survey rules out the easy explanation that utilities are reluctant to adopt AI. Seventy-eight percent say they are deploying or operationalizing at least one AI application to manage interconnection demand, meaning the queue of customers waiting for permission and capacity to plug into the grid. Seventy-two percent report bigger innovation budgets this year, and only 1% say they have no plans to work with early-stage technology companies.

    What has not improved is the time it takes to turn an experiment into standard practice. Eighty-four percent of organizations now need more than a year to move a project from pilot to full rollout, up from 78% in 2025 and 66% in 2024. The trend has worsened for three straight surveys even as money has flowed in, which points to a structural bottleneck rather than a funding one. Respondents cite a shortage of workers skilled in AI and the industry’s traditionally cautious culture, and spending patterns reinforce the picture: 59% of innovation dollars go to incremental improvements against 16% for transformational initiatives.

    That matters downstream because 74% of the same leaders say AI data center load is already affecting grid reliability. The pressure is present now; the tools meant to relieve it face a year-plus path to scale at most utilities. Data-center developers waiting in interconnection queues, utility planners fielding large-load requests, and the software vendors selling into utilities all operate on that clock. A tool that could, for example, help a utility study or approve a connection faster only helps once it is embedded in how the utility actually works.

    Reliability Moves Ahead of Net Zero

    The sharpest year-over-year shift in the survey concerns priorities. Asked to rank organizational priorities, 73% of utility leaders placed reliability in their top three, up from 43% in 2025. Net-zero goals fell from 54% to 16% over the same period.

    This is a forced ranking of top-three priorities, so it measures relative emphasis rather than abandonment of climate commitments. Still, a swing of that size in one year is a clear signal about what is occupying planning attention. When a single data-center campus can represent a large new load on a regional system, keeping the lights on becomes the dominant planning question, and decarbonization targets compete for a smaller share of management focus.

    Rate Cases Written for a Slower Era

    Utilities in the U.S. generally recover investment through rate cases, the regulatory proceedings in which state commissions decide what a utility can charge customers and what return it may earn. Eighty-seven percent of respondents say those frameworks, developed before the current demand boom, are limiting returns on innovation investment. If a software tool that frees up grid capacity earns a utility less than building new poles, wires and substations, the incentive structure itself slows adoption, which is consistent with the lengthening pilot timelines.

    The cost question cuts the other way for households. Eighty-three percent of respondents say the cost of building infrastructure to serve AI data centers is being passed on to residential customers through higher bills. That is the view of the utility leaders surveyed rather than a measured cost allocation, and the survey does not quantify it, but it is a notable admission coming from inside the industry, and it frames why regulators are likely to scrutinise who pays for data-center grid upgrades.

    Flexible Data Centers as a Grid Resource

    National Grid’s answer, alongside its investment activity, is flexibility. The company has become a founding member of the AI Energy Management Alliance, whose announced members include Google, NVIDIA, Anthropic, Emerald AI, RWE, Constellation and NRG. The group says it will push for policies encouraging flexible data centers that automatically reduce power use during peak demand, buffering nearby communities from price spikes.

    The supporting evidence cited is a UK pilot last December involving Emerald AI, a National Grid Partners portfolio company, together with National Grid and NVIDIA, which found AI software could cut data center energy use by more than a third in under a minute during simulated grid strain while protecting critical workloads. That is a meaningful proof of concept, though it was a single pilot under simulated conditions. Whether flexibility becomes a dependable planning resource depends on data-center operators contractually committing to curtail, and on utilities trusting those commitments enough to connect load sooner, which brings the question back to how fast planning practices and rules can change.

    Background

    National Grid supplies electricity and natural gas to more than 80 million people in the UK, New York and Massachusetts, and is running major transmission programmes including the Great Grid Upgrade in the UK and the Upstate Upgrade in New York. Its venture arm, National Grid Partners, launched in 2018, is based in Silicon Valley with offices in Boston, London and New York, and describes itself as the utility industry’s only Silicon Valley-based corporate venture capital group.

    National Grid also founded the NextGrid Alliance, which says it includes more than 1,000 senior decision-makers from over 170 utilities in 25 countries and has facilitated more than 500 introductions between utilities and startups. The survey arrives as U.S. utilities face surging requests to connect large AI data centers, a demand shift that is pressing on grid planning, reliability and how infrastructure costs are allocated among customers.

    Sources

    Source: 2026 Utility Innovation Survey: Industry leaders turning more to AI as data-center boom reshapes grid planning, National Grid Partners’ announcement of its third annual survey of U.S. utility innovation leaders, via PR Newswire.

  • Court Rejects Coal Plant Order, Narrowing DOE Emergency Power

    Court Rejects Coal Plant Order, Narrowing DOE Emergency Power

    TL;DR · 30-second read

    The Short Version

    A 64-year-old coal plant in western Michigan was supposed to shut down in May 2025. The federal government ordered it to keep burning coal anyway, saying the power was needed to stop blackouts.

    A federal appeals court has now ruled that order was unlawful, because there was no real emergency. Keeping the plant open has cost about $259 million so far, and Midwest households and businesses may end up paying much of it in their electricity bills.

    The government is still issuing similar orders at other plants, so the fight is not over.

    The U.S. Court of Appeals for the District of Columbia Circuit ruled Friday that the Energy Department exceeded its authority when it forced Michigan’s J.H. Campbell coal-fired power plant to operate past its scheduled May 2025 retirement. The Associated Press reported that a unanimous three-judge panel sided with environmental groups and the states of Michigan, Illinois and Minnesota, finding there was no genuine emergency under the Federal Power Act. Writing for the panel, Judge Cornelia Pillard described the statute’s emergency provision as “essentially a narrow, last-resort backstop” and called the reversal of the plant’s “long and carefully planned retirement” disruptive.

    The 64-year-old plant in West Olive, operated by Consumers Energy, has stayed online under successive orders signed by Energy Secretary Chris Wright, who argued the unit was needed for regional reliability. Keeping it running has cost roughly $259 million so far, according to new financial filings. Consumers Energy said it is reviewing the ruling and will keep the plant operating under a more recent Energy Department directive that extends through mid-November.

    Executive Summary

    The decision is the first appellate ruling to test how far the Energy Department can stretch emergency authority to keep generation online, and it lands squarely against the department. The court did not weigh in on whether the Campbell plant’s output was useful last winter. It held that usefulness is not the legal test: the emergency provision applies only when immediate, last-resort action is required and when the Energy Department in particular must act, rather than the states responsible for making sure enough generation exists to meet demand.

    That distinction matters well beyond one coal unit. Since President Trump’s January 2025 executive order declaring a national energy emergency, which cited demand growth from artificial intelligence and data centers, the administration has used the same authority to hold roughly half a dozen coal plants and one Pennsylvania oil-and-gas plant past their closure dates. The ruling gives challengers in Indiana, Colorado, Florida and Washington a precedent written by the court that most federal energy appeals run through.

    It also sharpens a question the industry has largely deferred. If aging fossil units cannot be conscripted by federal order, then the burden of serving new data center load falls back where the court says it belongs, on state regulators, regional grid operators and the developers themselves. Emergency orders were never a capacity plan. They are now a considerably less reliable one.

    A Backstop, Not a Planning Tool

    The Federal Power Act’s emergency provision, Section 202(c), lets the Energy Department order a power plant to run during a sudden crisis. It was written for hurricanes, fuel shortages and deep freezes, not for structural shortfalls that everyone can see coming years out. The D.C. Circuit read it that way, holding that the authority is “triggered only when there is a need for immediate, essentially last-resort action and the circumstances require action by DOE in particular, as opposed to action by the state or states responsible for resource adequacy.” Resource adequacy is the industry term for having enough generation on hand to meet peak demand, and in the United States it is primarily a state and regional grid operator responsibility.

    The second half of the holding is the part utilities will read twice. Reversing a long-planned retirement, the court said, is itself disruptive. That reflects operational reality. A plant scheduled to close sheds staff, winds down coal supply contracts, defers environmental capital spending and is replaced in the resource plan by something else. Restarting that machinery is not free, and the court treated the disruption as a cost of the order rather than a neutral act of caution.

    It is worth being precise about what the court did not decide. The panel reviewed statutory authority, not engineering. The Energy Department’s specific claims, that Campbell delivered more than 650 megawatts daily from January 21 to February 1 and that coal output in affected regions rose 25 percent at the peak of the winter storms, were not rejected as facts. Its broader claim that the orders “likely saved hundreds of lives” is a causal inference the department has not published supporting analysis for. And if the output genuinely was needed during those storms, that points to a resource adequacy gap which the ruling says states and grid operators, not emergency orders, are supposed to close.

    The $259 Million Question

    The hard number in this story is the cost: roughly $259 million to keep one 64-year-old unit running past its retirement date. Costs from reliability orders of this kind are typically recovered through regional rates, which is why the challengers, and Michigan’s attorney general, framed the case around Midwest ratepayers footing the bill for a plant their own utility had planned to close. Sierra Club attorney Sanjay Narayan called the ruling a victory for families “paying to keep this old, expensive and dirty power plant online.”

    Advocacy framing aside, the underlying economics are not really contested. A unit gets a retirement date because its running costs, maintenance burden and emissions compliance no longer pencil out against alternatives. An emergency order does not change that arithmetic; it transfers the loss to someone else. Neither Consumers Energy nor the Energy Department has published the plant’s operating economics under the orders, so the $259 million figure is the only quantified measure of what the intervention has cost, and the ruling leaves open who ultimately absorbs it.

    For large electricity buyers, this is the cost-allocation fight in miniature. Reliability insurance for a region has to be paid for by somebody. When it is bought through an emergency order rather than a capacity market or a bilateral contract, the payer is chosen administratively and litigated afterward. That is a poor foundation for a ten-year power budget.

    What AI Load Growth Actually Needs

    The January 2025 executive order invoked artificial intelligence and data center growth as justification for a national energy emergency. Set the scale side by side. Campbell’s contribution during the storm period was a bit over 650 megawatts, which the Energy Department described as enough for hundreds of thousands of homes. It is also roughly the appetite of a single large AI training campus of the kind being announced across the Midwest and Mid-Atlantic. Holding a handful of aging units online buys time measured in months and capacity measured against one or two hyperscale projects.

    The practical takeaway for developers is that announced retirement dates just became more credible as planning inputs. Siting a campus on the assumption that a nearby fossil unit will be kept alive by federal order is now a materially riskier bet. The binding constraints remain what they were: interconnection queues, the multi-year backlog of requests to connect new plants and large loads to the grid, plus transformer and turbine lead times. None of those are addressed by an emergency order.

    The court’s federalism framing pushes the pressure toward state commissions and regional grid operators, and through them toward large customers. Expect more of what is already emerging: on-site or behind-the-meter generation, long-term contracts that fund firm capacity directly, and demand flexibility arrangements in which a data center agrees to curtail during system peaks in exchange for faster service. Those are slower and more expensive than a federal directive, but they do not expire when a panel of judges rules.

    The Orders Keep Coming

    The administration’s response was immediate. Hours after the ruling, Secretary Wright issued a new emergency order keeping the TransAlta-operated Centralia plant in Washington online; it had been scheduled to close at the end of 2025. Similar orders cover plants in Indiana, Colorado and Florida, and a Pennsylvania oil-and-gas plant has been directed to keep its turbines running as a hedge against Mid-Atlantic shortages. Consumers Energy, for its part, will keep Campbell running through mid-November under a separate directive while it reviews the decision.

    Each order stands on its own record, so the ruling does not automatically void the others. It does hand challengers a template, and because the D.C. Circuit hears most federal energy appeals, its reasoning carries unusual weight. The Energy Department has not said whether it will seek rehearing or Supreme Court review, which is the near-term question for anyone modeling how long this authority remains usable.

    For plant owners, an emergency order is revenue with a legal tail. Payments made under an order later found unlawful invite disputes over recovery and potential disallowance, and the uncertainty itself imposes planning costs on utilities trying to decide whether to retire, retrofit or resell a marginal unit. The cleanest reading of Friday’s decision is not that coal must close on schedule. It is that the federal government cannot unilaterally decide it should not.

    Background

    The J.H. Campbell plant has operated on Michigan’s west side for 64 years and is run by Consumers Energy, the regulated utility subsidiary of CMS Energy. Like much of the aging coal fleet in the Midwest grid region, it was slated for closure as operating costs, maintenance demands and cleaner alternatives shifted the economics. Its retirement date of May 2025 had been in utility resource plans for years before the Energy Department intervened.

    Section 202(c) of the Federal Power Act, the provision at issue, has historically been used sparingly and briefly, typically during hurricanes, fuel disruptions or extreme cold snaps. That changed after President Trump’s January 2025 executive order declaring a national energy emergency, which cited electricity demand growth from artificial intelligence and data centers. Since then the department has used the authority to hold roughly half a dozen coal plants past their closure dates, plus an oil-and-gas plant in Pennsylvania, producing litigation in several states of which the Michigan case is the first to reach an appellate decision.

    Sources

    Source: Federal court rejects Trump order keeping Michigan coal plant open — Associated Press report on the D.C. Circuit ruling that the Energy Department exceeded its authority in ordering the J.H. Campbell coal plant to operate past its scheduled retirement.

  • TVA Creates Data Center Rate Class, Approves 2026 IRP Amid AI Load Growth

    TVA Creates Data Center Rate Class, Approves 2026 IRP Amid AI Load Growth

    The Tennessee Valley Authority’s Board of Directors on August 20, 2026, approved a package of actions aimed at insulating ordinary ratepayers from the cost of surging data center demand: a modified wholesale rate structure that creates a new data center rate, adoption of the 2026 Integrated Resource Plan projecting a need for 11 to 32 gigawatts of additional generation by 2040, and an FY2027 budget that includes more than $13 billion in planned investment through FY2029.

    TVA — the nation’s largest public power supplier, serving roughly 10 million people across seven southeastern states — also confirmed construction of 4,120 megawatts of new TVA-owned capacity, with another 3,000 megawatts under evaluation.

    Executive Summary

    The headline action is structural, not financial: TVA is changing who pays for growth. By carving data centers into their own wholesale rate class, the utility says it will align charges with the actual cost of serving that load and prevent residential and manufacturing customers from subsidizing the infrastructure that hyperscale computing requires. The move follows TVA’s signing of the Ratepayer Protection Pledge, a national initiative built around the same cost-causation principle — the idea that large power users should cover the full cost of the energy and grid capacity their facilities demand.

    The rate change lands alongside two planning decisions that frame its scale. The 2026 Integrated Resource Plan — the long-range study utilities use to map future generation needs — projects the Valley region will need between 11 and 32 gigawatts of additional capacity by 2040, a range wide enough to signal genuine uncertainty about how much AI-driven demand will actually materialize. The FY2027 budget backs the near-term end of that build-out with more than $13 billion planned through FY2029, including over $1 billion annually to maintain the existing fleet and transmission system.

    For the data center industry, the signal is unambiguous: in TVA territory, as in a growing number of utility service areas, large computing loads will be priced as a distinct customer class with distinct cost responsibility — and other regulated utilities will be studying this template closely.

    Ring-Fencing Ratepayers Is Becoming Utility Orthodoxy

    The core mechanism here is a familiar one in utility economics: cost allocation by customer class. Utilities have long charged residential, commercial, and industrial customers differently because they impose different costs on the system. What is new is treating data centers — historically lumped in with large industrial users — as a class of their own. The rationale is that hyperscale facilities demand power at a scale, density, and speed that requires dedicated generation and transmission investment; without a separate rate, those costs spread across everyone’s bills. TVA’s framing, echoed in the Ratepayer Protection Pledge it recently signed, is that data centers should carry the full freight of the infrastructure they trigger.

    The release is explicit about the political economy driving this. Board Chair Mitch Graves invoked ‘hardworking American families and small businesses’ not being ‘left carrying the cost’ of AI’s electricity appetite. That language reflects a real pressure point: public concern that AI load growth is inflating household electricity bills has become one of the most potent consumer-energy narratives in the country. A public power agency with no shareholders — TVA answers to its board and, ultimately, to Congress — has strong incentives to get ahead of it. What the release does not disclose is the actual design of the new rate: no price levels, demand-charge structure, contract terms, or eligibility thresholds are given, which makes it impossible to judge yet how protective — or how burdensome to data center developers — the class will be in practice.

    An 11-to-32 Gigawatt Question Mark

    The 2026 Integrated Resource Plan’s projection that the region needs 11 to 32 gigawatts of additional capacity by 2040 deserves attention for its width as much as its size. The high end is nearly triple the low end — a spread that honestly reflects how speculative long-range AI demand forecasting remains. Data center interconnection queues across the country are known to contain duplicate and speculative requests, and utilities that build to the high case risk stranded assets if projects evaporate, while building to the low case risks reliability shortfalls if they don’t. TVA’s approach — approving a plan that ‘identifies a host of diverse generation mixes’ rather than committing to one — preserves optionality, which is prudent, though it also defers the hard resource choices.

    The concrete commitments are nearer-term: 4,120 megawatts of new TVA-owned capacity under construction, 3,000 megawatts under evaluation, and more than $13 billion planned through FY2029. Against even the low-end 11-gigawatt need, that construction pipeline covers roughly a third — meaning substantially more investment decisions lie ahead. The new data center rate class is arguably what makes that math workable: if large loads pay their full cost of service, incremental capacity can be financed against contracted demand rather than socialized risk.

    A Template Other Utilities Will Study — With Caveats

    TVA occupies an unusual position that makes it both a bellwether and an imperfect template. As a self-supporting federal corporate agency, its board sets rates directly rather than litigating them before a state utility commission, so it can move faster than investor-owned utilities, which must take rate-class changes through contested regulatory proceedings. Its starting point is also enviable: the release notes TVA’s residential rates are lower than those paid by 80% of customers of the top 100 U.S. utilities, and its industrial rates lower than 90%. A low-cost incumbent can impose stricter terms on data centers without immediately pricing itself out of site-selection shortlists.

    Still, the direction of travel matters for everyone in the digital infrastructure value chain. For data center developers and their tenants, specialized rate classes generally mean longer-term contracts, minimum-payment obligations, and less ability to externalize infrastructure risk — raising the cost floor but also, potentially, giving utilities the confidence to build capacity faster. For competing regions, TVA’s combination of cheap incumbent power, a massive build-out, and an explicit consumer-protection posture is a competitive statement: the Valley wants AI load, but on terms its board can defend publicly. Buyers evaluating the region should read the new rate’s fine print, once published, before assuming historical TVA pricing applies to them.

    Background

    Created by Congress in 1933, the Tennessee Valley Authority has grown into the largest public power supplier in the United States, serving roughly 10 million people through local power companies across seven southeastern states while funding itself entirely from electricity sales. Its service territory has become one of the country’s most active data center growth corridors, and TVA has been positioning for that demand: the utility recently reported $6.6 billion in operating revenues on nearly 82 billion kilowatt-hours of sales for the first six months of fiscal 2026, and was selected for a $400 million U.S. Department of Energy grant to accelerate next-generation nuclear power.

    The August 2026 board actions arrive amid a national debate over who should pay for AI-driven load growth. Utilities across the country face record interconnection requests from hyperscale computing projects, and regulators, consumer advocates, and industry groups have increasingly converged on special rate classes and cost-causation pricing as the mechanism to keep that growth from flowing into household bills.

    Source: TVA Board Protects Consumers, Strengthens Reliability Amid Rising Power Demand — Tennessee Valley Authority press release via PR Newswire, August 20, 2026, announcing a new data center rate class, 2026 IRP approval, and the FY2027 budget.

  • Virginia’s 3.8 GW Data Center Trip Shows Why Ride-Through Is Becoming a Grid-Access Test

    Virginia’s 3.8 GW Data Center Trip Shows Why Ride-Through Is Becoming a Grid-Access Test

    TL;DR · 30-second read

    The Short Version

    On July 22, an ordinary electrical fault on a power line in northern Virginia caused a cluster of data centers, the buildings full of computers that run the internet, to disconnect from the grid almost at once.

    In minutes, about 4% of all the electricity being used across 13 states and Washington, D.C. vanished from the system.

    The organization that runs that grid says the data centers were too jumpy. It is now considering rules requiring them to stay connected through brief power glitches. If those rules arrive, how a data center reacts to a glitch could decide whether it gets connected at all.

    Utility Dive reported that PJM Interconnection, the grid operator for 13 Mid-Atlantic and Midwest states and the District of Columbia, is considering new interconnection reliability requirements for “computational loads” such as data centers and crypto-mining facilities. The requirements under consideration include “ride-through” standards, which require equipment to stay connected through brief voltage and frequency disturbances rather than disconnecting.

    The trigger was a July 22 event in which about 3,800 MW of data center load in northern Virginia tripped offline in two waves after a fault on a 230-kV transmission line in Dominion Energy’s zone. PJM’s total load fell about 3.8%, from 99,984 MW to 96,205 MW. PJM called it the largest such event in its history.

    Executive Summary

    PJM is evaluating whether to expand its reliability requirements for large computing loads after data centers disconnected from the grid in response to what its Operating Committee chair called “a normally cleared fault.” In other words, the grid did what it was supposed to do, and the data centers dropped off anyway. PJM staff told an August 6 Operating Committee meeting that the facilities appear to be disconnecting too early.

    This matters because it shifts part of the grid-reliability burden onto the load side. Until now, the obligation to stay online through disturbances has fallen mainly on power plants. PJM’s position is that a data center cluster large enough to remove nearly 4% of system demand in minutes now needs the same kind of behavioral rules. As David Souder, PJM’s executive director of system operations, put it, those requirements need to be “in place before the load comes on the system.”

    The timing also matters. The North American Electric Reliability Corp. (NERC) is building national standards for computational loads under a Federal Energy Regulatory Commission directive. PJM said, however, that NERC will not address voltage and frequency ride-through until sometime next year. That leaves PJM weighing whether to act in the meantime.

    How a Routine Fault Became a 3,800 MW Problem

    Transmission faults happen constantly. A line gets struck by lightning or contacts a tree, protective relays isolate it within a fraction of a second, and voltage briefly sags on nearby parts of the network before recovering. Power plants are expected to “ride through” that sag, meaning they stay connected and keep producing. Data centers are generally built with the opposite instinct. Their electrical systems are designed to protect servers from bad power, so when voltage moves outside a set tolerance window, they switch to batteries and on-site generators and stop drawing from the grid.

    For a single facility, that is sensible engineering. For a cluster, it becomes a system event. When thousands of megawatts of demand leave the grid at the same moment while generation keeps running, supply suddenly exceeds demand. Frequency and voltage swing, and the operator has to rebalance quickly. PJM said the July 22 event caused “a high imbalance between generation and load” and large swings in both voltage and frequency, and that it dispatched reactive power resources to bring system voltage down. PJM’s Operating Committee chair, Emanuel Bernabeu, described the data centers as “too sensitive to the kind of voltage that they like.”

    The Event Sizes Are Growing Faster Than the Rules

    PJM listed two earlier events in the same Dominion zone. Each caused a sudden load transfer of about 1,500 MW, one in 2024 and one in 2025. The July 22 event was roughly two and a half times that size. Three incidents in one region do not make a statistical trend, but the direction is consistent with how northern Virginia is building out: more and larger facilities, clustered on the same transmission network and often reacting to the same disturbance at once. For scale, 3,800 MW is on the order of the output of three large nuclear reactors.

    The grid handled it. PJM said it brought its Area Control Error, the running measure of the mismatch between supply and demand, back within limits in nine minutes, against a NERC standard of 30 minutes. That is a good operational result, and it should not be read as a near miss. The concern PJM raised is forward-looking: each new facility connected under current practice adds to the amount of demand that could disappear in a single disturbance. At some point the operator has to either hold more balancing capacity in reserve or require the load to behave differently. PJM’s move signals it prefers the second option.

    Ride-Through Moves From Design Choice to Condition of Connection

    This is the substance behind the headline. PJM is framing the fix as an interconnection reliability requirement, a condition attached to connecting to the grid, rather than a best-practice guideline. Souder’s remark that requirements must be in place “before the load comes on the system” points to the interconnection queue as the enforcement point. If PJM follows through, projects now in development would need to show that their electrical design keeps them connected through a normally cleared fault. Retrofitting that behavior after energization is harder and more contested.

    The practical effects would be felt in specific places. Developers and colocation operators would need to revisit the voltage and frequency tolerance settings on their uninterruptible power supplies and switchgear, and possibly the hardware itself. Hyperscale tenants would need to accept that their facilities ride out disturbances their servers were previously shielded from. Equipment vendors whose systems can demonstrate grid-friendly behavior would gain a selling point. Utilities such as Dominion, whose zone hosts the world’s largest data center cluster, would gain a clearer technical basis for connection studies. The rules would cover crypto miners too, because PJM used the broader category of “computational loads.” Mining loads are generally more flexible about interruption, but they are no less able to trip off in a block.

    There is a real engineering tradeoff, and it deserves an even-handed hearing. Data center operators set tight tolerances to protect equipment and meet uptime commitments to customers, and loosening them carries risk for the operator. PJM’s argument is that the risk of undisciplined load, which falls on everyone connected to the grid, now outweighs the private risk. Where the thresholds land, and whether PJM offers alternatives such as coordinated or staggered transfer settings, will determine how costly the change becomes.

    A Gap Between Regional Urgency and National Standards

    NERC is scheduled to finalize registry criteria and initial reliability standards for computational loads by December 31, and to produce a plan by March for additional standards. According to PJM, ride-through for minimum voltage and frequency will not be addressed until sometime next year. Meanwhile, Northern Virginia continues to add capacity. That leaves PJM choosing between acting regionally now and risking a mismatch with a later national standard, or waiting and connecting more load under today’s practices. Wharton’s reference to “existing and future industry ride-through standards and practices” suggests PJM intends to align with NERC where it can, without waiting for NERC to finish.

    Background

    Northern Virginia, largely within Dominion Energy’s service zone, hosts the largest concentration of data centers in the world. Rapid growth in data center demand there and elsewhere in PJM’s 13-state footprint has made large computing loads a central grid-planning issue. PJM has reported sudden data center load transfers of about 1,500 MW in both 2024 and 2025, and NERC issued alerts on sudden data center load losses earlier in 2026, including a Level 3 alert in May calling for mandated actions.

    Grid reliability rules in North America are set by NERC and approved by the Federal Energy Regulatory Commission. Regional operators such as PJM can add their own interconnection requirements. Historically those rules focused on generators. The rise of very large, clustered loads has prompted FERC to direct NERC to develop registry criteria and reliability standards specifically for computational loads.

    Sources

    Source: PJM eyes data center, crypto reliability requirements after 3.8 GW of load trips offline (Utility Dive, August 12, 2026), covering PJM’s response to the July 22 northern Virginia load-loss event.

  • Texas’s 474 GW Pause Shows Why AI Data Centers Can’t Count on Speed-to-Power

    Texas’s 474 GW Pause Shows Why AI Data Centers Can’t Count on Speed-to-Power

    TL;DR · 30-second read

    The Short Version

    Companies want to plug so many new data centers into the Texas power grid that their combined requests add up to several times more electricity than the whole state has ever used at one moment. Data centers are the giant computer warehouses that run artificial intelligence.

    The governor has ordered a check of every data center waiting in line. The organization that runs the state’s grid has put its review on hold while that happens.

    Texas sold itself as the fastest place to get power. For now, it is a waiting line.

    Texas Gov. Greg Abbott has called for an audit of all data centers in the Electric Reliability Council of Texas (ERCOT) interconnection queue, the list of projects waiting for permission and studies to connect to the state’s main power grid. Utility Dive reported on August 5, 2026 that the audit led ERCOT to delay its Batch Zero review process, and that the queue now holds an estimated 474 gigawatts (GW) of interconnection requests.

    Executive Summary

    The state that built its data center pitch on fast access to power has stopped processing the largest group of new requests it has received. The governor’s audit covers every data center in ERCOT’s queue, and ERCOT’s Batch Zero review, the process that would move those large loads toward connection, has been pushed back while the audit proceeds.

    The figure that frames the decision is 474 GW. That is far more than ERCOT has ever served at peak demand, which means the queue cannot describe what will actually be built. It describes what developers hope to build, often with overlapping requests for the same eventual capacity. An audit is the state’s way of forcing that list to reflect reality before engineers spend time studying it.

    For companies planning AI campuses, the practical consequence is timing. A Texas site that looked like a fast route to energized capacity now sits behind an audit whose outcome will determine who moves forward, and in what order.

    A Queue Larger Than the Grid It Wants to Join

    An interconnection request is an application to connect a large new user of electricity, or a new power plant, to the transmission grid. Filing one is relatively inexpensive compared with building the project, so developers often file early and in several places at once, keeping options open on land, tenants and financing. The result is a queue that measures ambition rather than construction.

    At an estimated 474 GW, ERCOT’s queue is several times the most electricity the Texas grid has ever delivered at a single moment. No grid could add that much load on any planning horizon that matters to a data center developer, so most of those requests will not be built as filed. Some are duplicates of the same project at different sites. Some are placeholders for customers who have not signed. Some are real and ready. From the grid operator’s side, those categories look identical until someone checks.

    That is the problem an audit addresses. Studying every request at face value would tie up transmission planners on projects that will never exist, and it would distort the models that decide what new lines and substations Texas needs.

    Why Speed-to-Power Has Become a Waiting Line

    Speed-to-power, meaning how quickly a site can actually receive electricity from the grid, has become the deciding factor in where AI data centers go. Chips, buildings and cooling can be bought on predictable schedules. Grid capacity cannot. Texas won a large share of recent projects partly because its market structure and its largely self-contained grid were seen as moving faster than regulated utility territories elsewhere.

    Batch Zero was ERCOT’s first grouped review of large-load requests. A batch process is efficient because it studies many projects together, but that design also means a delay to the batch is a delay for every project inside it. When the governor’s audit prompted ERCOT to hold the review, each developer in that group lost its place on the calendar, regardless of how far advanced its own project was.

    The people who feel that first are developers holding land, equipment orders and tenant negotiations timed to a Texas energization date; the AI companies and cloud providers who planned to lease that capacity; and the lenders whose construction financing assumes power arrives on schedule. None of them can hedge a grid review. A site that is otherwise ready produces no revenue until it is connected.

    What an Audit Can and Cannot Fix

    An audit can shrink the queue to projects with real backing, which would make the eventual studies faster and more accurate. Done well, it rewards developers who have secured land, financing and customers, and it clears space that speculative requests were occupying. That would be a better outcome for serious projects than the status quo, even if it costs them time now.

    An audit cannot produce generation or transmission. Even a heavily trimmed queue may still exceed what the grid can add quickly, so the underlying constraint remains physical. It also carries execution risk: if the criteria are unclear or change during the process, credible projects could be delayed alongside speculative ones, and developers may respond by pursuing on-site generation or by filing in other markets instead.

    A Test Case Beyond Texas

    Grid operators across the United States face the same pattern: large-load requests arriving faster than they can be studied, with no reliable way to tell firm demand from optionality. Texas is the first to make the screening step this visible, with a state-level audit sitting ahead of the grid operator’s review.

    How it goes will be watched closely. If the audit produces a credible, smaller queue and Batch Zero resumes on a clear schedule, other regions may copy the approach. If it drags on, the lesson for AI infrastructure planners will be that fast-power markets can slow abruptly, and that grid access needs to be treated as a risk on every site plan, not a given.

    Background

    ERCOT manages the grid that serves most of Texas and operates under the oversight of the Public Utility Commission of Texas. Because its network is largely isolated from the rest of the country’s grids, ERCOT has limited ability to import power and must plan new generation and transmission largely within the state.

    Over the past several years Texas attracted a large share of new data center development, including AI-focused campuses, on the strength of available land, a competitive power market and a reputation for connecting large users quickly. The state legislature responded in 2025 with Senate Bill 6, which set new rules for large electricity users, including disclosure of duplicate interconnection requests and provisions for curtailing large loads during grid emergencies. ERCOT’s Batch Zero process was designed to handle the resulting wave of large-load requests in a coordinated group.

    Sources

    Source: Facing an estimated 474 GW of interconnection requests, Texas hits pause on data centers (Utility Dive), on Gov. Greg Abbott’s audit of data centers in ERCOT’s interconnection queue and the resulting delay to Batch Zero.

  • Texas Audit’s Up-to-$15B Hit Shows AI Racks Make Grid Delay a Financing Risk

    Texas Audit’s Up-to-$15B Hit Shows AI Racks Make Grid Delay a Financing Risk

    TL;DR · 30-second read

    The Short Version

    On August 3, Texas Governor Greg Abbott paused new data center connections to the state’s main power grid while officials check every project waiting in line.

    Research firm BloombergNEF says the pause could hold back data centers that want more than half as much electricity as Texas has ever used at its busiest moment.

    Artificial intelligence drives the expensive part. Buildings filled with artificial intelligence chips earn roughly ten times the rent of ordinary computer warehouses. That means even a few months of waiting could cost projects up to about $15 billion in lost income.

    Texas Gov. Greg Abbott’s August 3 order pausing all new data center connections to the Electric Reliability Council of Texas (ERCOT) grid until a comprehensive audit is complete could delay 49.8 GW of data center demand. That is nearly 20% of the 253-GW U.S. data center development pipeline. POWER Magazine reported the figure from an August 5 BloombergNEF (BNEF) report, which also estimates that a three-month slip in near-term Texas capacity additions could cost projects just over $8 billion by the first quarter of 2027 if 60% of the delayed capacity is AI-related, and roughly $15 billion if all of it is.

    Abbott directed the Public Utility Commission of Texas (PUCT) and ERCOT to verify and audit every data center project in a large-load interconnection queue of roughly 474 GW before any more advance. Within hours, ERCOT issued Market Notice M-A080326-01, which suspended the first deliverable of its new Batch Zero interconnection process. That deliverable had been due August 7.

    Executive Summary

    The governor presents the audit as a reliability measure. ERCOT’s queue of pending large-load requests is more than five times the grid’s 91.3-GW peak demand, and some data centers failed to comply with a state survey of water and power use. BNEF’s report reads the timing differently. It notes that Abbott faces reelection in November and says the pause is likely meant to take the data center issue off the table until after the vote.

    The more durable finding is economic. BNEF’s cost range depends almost entirely on how much of the delayed capacity is AI compute. The firm estimates that AI capacity earns about $1.76 billion per gigawatt per month, while a colocation-powered cloud shell in Dallas earns up to $175 million. As a result, a regulatory pause of a few months is no longer a scheduling inconvenience for AI campuses. It is a revenue and financing event. BNEF also warns that the audit could run into the 2027 legislative session, which would give lawmakers a chance to rewrite the rules that govern how Texas connects large loads.

    Why AI Load Sets the Price of a Grid Delay

    BNEF’s scenario is deliberately narrow. It takes the ERCOT data center capacity forecast for the third quarter of 2026 through the first quarter of 2027, assumes it all slips to the second quarter of 2027, and measures the rental revenue that disappears in the meantime. The result swings widely. At a 10% AI mix, cumulative revenue at risk is about $2 billion. At a 60% AI supermajority, it is just over $8 billion. At 100% AI compute, it reaches roughly $15 billion. The megawatts are the same in every case. Only the tenant changes.

    The mechanism lies in the two rental benchmarks behind the model. Citing CBRE data, BNEF says a colocation-powered shell for traditional cloud racks in Dallas can earn up to $175 million per gigawatt per month. Using GPU rental prices from Silicon Data, it estimates AI compute capacity at around $1.76 billion per gigawatt per month, roughly ten times as much. (A GPU, or graphics processing unit, is the chip that trains and runs AI models.) So each month an AI hall waits for power forgoes about ten times the revenue of a conventional cloud hall of the same size.

    This is what turns interconnection timing into a financing question. AI campuses are usually underwritten on the assumption that expensive compute starts earning soon after the building is energized. A pause set by a state audit rather than by construction progress is hard for a developer to mitigate and hard for a lender to model. The people most exposed are those financing AI-heavy Texas projects near energization: developers, their GPU-cloud tenants, and their lenders. Conventional colocation projects face the same delay but carry a far smaller revenue gap.

    The 49.8 GW Headline Versus the Capacity Actually Being Built

    The 49.8-GW figure measures the demand whose progress could stall. It does not measure what would have been switched on this year. BNEF forecasts only 1.2 GW of ERCOT data center additions between the second quarter of 2026 and the first quarter of 2027. Its tracked Texas pipeline of 50 GW breaks down into 36 GW at an early stage, 9 GW committed with land, power and approvals, and 5 GW under construction. By 2030, BNEF expects Texas data center capacity in ERCOT to reach 17.2 GW, far below the roughly 204 GW eligible for Batch Zero study.

    This gap cuts both ways in the political argument. It supports Abbott’s premise that a queue five times peak demand needs scrutiny: BNEF itself calls it speculative and says it lacks project transparency. It also shows that the near-term dollar exposure sits in a small, real slice of capacity, the projects close enough to completion to lose revenue in 2026 and early 2027. A verification process that is fast for committed projects and slow for speculative ones would target the problem the governor describes. A blanket pause does not make that distinction.

    Batch Zero Stalls, and the Calendar Becomes the Risk

    Batch Zero, approved in June, lets ERCOT study large loads in groups rather than one at a time, so that grid capacity is allocated more efficiently and connections move faster. The governor’s order halted it at its first step. ERCOT said it will not tell transmission and distribution providers how each large load is classified by August 7. It also plans to seek a good-cause exception from its Planning Guide timelines before the PUCT’s August 20 open meeting.

    The audit also overlaps with rules already underway. Senate Bill 6 already requires site-control documentation, $50,000 per MW in financial security, disclosure of duplicate interconnection requests at other sites, and reporting of on-site backup generation. The PUCT is still writing these requirements into 16 TAC § 25.194, with adoption expected in September and a statutory deadline of December 31, 2026. BNEF warns that an onerous audit could extend into the 2027 legislative session, potentially as late as April, and open the SB 6 framework to further restrictions.

    For projects already in the queue, there is no quick fix. BNEF says a delay until April or May 2027 is too short for data centers to buy and build behind-the-meter generation, meaning on-site power plants, as a hedge. The 294 GW of requests that were not eligible for Batch Zero face a different outcome. If new legislation arrives, those later projects may lean toward on-site generation and storage from the start.

    A Reliability Case, a Political Read, and a Pattern Across States

    Both explanations for the audit deserve scrutiny. The governor’s reliability case rests on documented facts: a queue five times record peak and a recorded failure by some data centers to answer the PUC’s water and power survey. Still, BNEF notes that most of the information the audit might gather is already required under SB 6 or other rules, which raises the question of what the audit adds. BNEF’s electoral reading is an inference from timing and context: a 15-hour public hearing, and the lieutenant governor’s call to pause $33 billion in planned transmission spending toward western Texas. It is plausible, but it is interpretation, not documentation.

    Texas is also not acting alone. New York’s Executive Order 62, signed July 14, imposed a statewide moratorium on new hyperscale data centers of 50 MW or more. Illinois paused Data Center Investment Program agreements from July 1. Florida’s SB 484, effective July 1, bars utilities from shifting large-load costs to residential and small-business customers. BNEF concludes that community opposition is becoming a material constraint even in markets that have courted the industry. Abbott himself had recently called Texas “the epicenter of AI development.” Unlike New York’s measure, the Texas action is a verification precondition rather than a moratorium. Some of the industry has welcomed it: QTS Data Centers’ co-CEOs endorsed the governor’s leadership and called for clear guardrails.

    Background

    Texas has been one of the fastest-growing U.S. data center markets. It offers abundant land, a competitive power market, and a state government that has actively courted the industry, including after Google’s $40 billion investment announcement. That growth has flooded ERCOT’s interconnection queue, the waiting list of large electricity users seeking grid connections, with requests far exceeding what the grid serves today. In 2025 the legislature passed Senate Bill 6 to impose financial and disclosure requirements on large loads, and ERCOT designed Batch Zero to process those requests in groups.

    In 2026, pushback has grown across several states. New York imposed a moratorium on large new data centers, Illinois paused its data center incentive agreements, and Florida restricted how utilities can allocate data center costs to other customers. In Texas, a 15-hour public hearing and the lieutenant governor’s call to pause $33 billion in transmission spending came shortly before the governor’s audit order.

    Sources

    Source: Texas Audit Could Delay 49.8 GW of Data Center Load, Cost Projects Up to $15 Billion, BNEF Warns (POWER Magazine), coverage of BloombergNEF’s August 5, 2026 report on the ERCOT data center audit.

  • PJM’s 3.1 GW Data Center Dropout Shows AI’s Other Grid Risk: Load That Leaves

    PJM’s 3.1 GW Data Center Dropout Shows AI’s Other Grid Risk: Load That Leaves

    TL;DR · 30-second read

    The Short Version

    When one power line failed near Washington, DC, a wave of data centers (the warehouse-sized buildings full of computers that run the internet and AI) unplugged from the power grid within seconds and switched to their own backup power.

    Together they had been using about 3% of the electricity on a grid that serves 67 million people. Losing that much demand at once threw the system off balance. Lights flickered from Virginia to Chicago, and it took more than 10 minutes to settle.

    It was twice as big as a similar scare in 2024, and data centers keep multiplying. The proposed fix is to make them stay connected through brief hiccups, often by using giant batteries.

    A single power line failure outside Washington, DC, this past week caused a wave of Northern Virginia data centers to switch to backup power at nearly the same moment, TechCrunch reported. According to PJM data, about 3.1 gigawatts of demand disappeared from the PJM Interconnection grid in roughly 30 seconds. After a partial recovery, more facilities dropped off, and the grid’s surplus peaked at 3.49 gigawatts. Stabilizing took another 11 minutes. A line fault like this one normally takes only a few seconds to recover from.

    According to Reuters, the disconnected load was about 3% of PJM’s demand at the time. Sensor data from the startup Ting Labs showed voltage spiking across the grid from Northern Virginia to Chicago. There was no blackout, but lights flickered across the region. The event was roughly twice the size of a 2024 PJM incident in which 60 data centers disconnected at once and removed 1.5 gigawatts.

    Executive Summary

    Most discussion of data centers and the power grid asks whether there is enough electricity to feed them. This event shows the opposite failure: a cluster of very large customers that all leave the grid at once when they sense trouble. Each facility’s protective logic behaved as designed and switched to on-site backup power when voltage dipped. Together, those individually sensible decisions turned a routine line fault into a regional disturbance that lasted more than ten minutes.

    Two remedies are being proposed. The first is coordination. Ali Zain Banatwala, a senior market models specialist at the Independent Electricity System Operator, argues that neighboring loads need a way to disconnect and reconnect one after another rather than all together. The second is ride-through, which means keeping facilities connected through brief disturbances. Ricardo de Azevedo, CTO of ON.Energy, whose company sells campus-scale battery systems built for that purpose, said ERCOT, the Texas grid operator, will require large loads to ride through disruptions.

    The stakes rise with the load. Synapse Energy Economics put data centers at about 6% of PJM’s load in 2024 and projects 24% by 2040. The potential size of a synchronized dropout grows with that share unless the facilities are built to behave differently.

    AI’s Other Grid Problem Is Load That Leaves

    An electric grid has to keep supply and demand in near-perfect balance from moment to moment. When a line goes down, the grid normally absorbs the loss and rebalances within seconds. This time, the voltage dip from the fault reached many data centers sitting close together. Their protection systems are designed to make split-second decisions to safeguard the computers inside, and they moved the facilities onto backup power within a few seconds of each other. The grid lost about 3.1 gigawatts of demand in roughly 30 seconds. Generators were suddenly producing more electricity than customers were using, and voltage jumped.

    The second wave is the detail grid planners should focus on. PJM’s grid appeared to recover partway before more loads dropped off, pushing the surplus to a peak of 3.49 gigawatts. In that pattern, the disturbance triggers disconnections, and the disconnections deepen the disturbance. That feedback is what stretched a seconds-long event into an 11-minute one. A gigawatt is roughly the output of a large power plant. In effect, the grid had to absorb the sudden departure of several power plants’ worth of customers.

    That is why the grid risk from the data center buildout is not only a question of supply. Operators are used to planning around the sudden loss of a large generator. Clustered data centers create a mirror-image contingency: a large block of customers lost all at once because of a single triggering event. Everyone on the grid is exposed to that. Households saw flickering lights, generators must ramp down fast, and the operator must hold capability in reserve for a contingency that grows as data center load grows.

    Concentration Turns a Local Fault Into a Regional Event

    Northern Virginia has the highest concentration of data centers in the world. That density is what made the disconnection synchronized, because one voltage dip reached many facilities almost at once. The effect traveled well beyond Virginia. Ting Labs runs a sensor network through household electrical outlets, and it recorded the voltage spike as far away as Chicago. PJM covers the territory from New Jersey to Illinois, serves 67 million customers, and is the largest grid operator in the United States.

    The trend line gives the event its weight. In 2024, 60 data centers disconnected together and removed 1.5 gigawatts. This time the figure was about 3.1 gigawatts, roughly double. Data centers were about 6% of PJM’s load then, and Synapse Energy Economics projects 24% by 2040. Two events are not a statistical series, and nothing here shows the next one will double again. The arithmetic still matters: if protective behavior stays the same while the share of load it governs roughly quadruples, the ceiling on a synchronized dropout rises with it.

    De Azevedo called the event “the canary in the coal mine” and said incidents involving large loads are “happening more and more.” That claim comes from a vendor of the remedy. The two PJM incidents, with their measured sizes, are the documented reference points.

    Two Fixes: Choreograph the Exit, or Don’t Leave

    The first approach accepts that data centers will disconnect but asks them to do it in order. “We need to figure a way for these loads that are located next to each other to sequentially either disconnect or reconnect,” Banatwala said. Staggered behavior would let grid operators write procedures in advance instead of reacting to a cliff. The hard part is coordination. The facilities belong to different owners, each has settings tuned to protect its own uptime, and they would need shared thresholds or a shared signal.

    The second approach is ride-through, meaning the facility stays connected through brief disturbances. ON.Energy’s version is an uninterruptible power supply, the battery backup that keeps servers running through outages, sized for an entire campus, including chillers and other equipment as well as servers. Batteries and power-conversion equipment sit between the grid and the facility, so the grid sees one steady, predictable load. The company says the system:

    • charges its batteries when the grid has surplus power;
    • discharges to the servers when supply dips;
    • follows the grid within milliseconds;
    • smooths the swings of AI training workloads that ramp power up and down.

    It says it is installing 3 gigawatts of these systems across four campuses.

    Those claims are specific enough to test. The test is whether a campus behind such a system stays connected and grid-friendly during a real fault like this one. The economics matter too. Sizing batteries and power electronics for a whole campus adds capital cost that the developer bears, while most of the benefit goes to the grid. Mandates may be what shifts that calculation, such as ERCOT’s ride-through requirement, which de Azevedo described.

    What Developers and Buyers Should Expect

    From a tenant’s point of view, the July event worked: the data centers switched to backup, and the computers presumably kept running. The cost of that decision fell on the grid and everyone else connected to it. This asymmetry is what makes the event a policy question rather than just an engineering one. Individual facilities have little reason to change behavior that protects their own uptime unless interconnection rules require it.

    For developers, the likely direction is toward grid connection terms that specify how a facility behaves during a disturbance, not just how much power it draws. ERCOT is moving that way, according to de Azevedo. PJM, where both incidents occurred, is where the question is now most visible. For suppliers of storage, power conversion and switchgear, the grid-facing layer of a campus becomes part of the design requirement. For colocation buyers, it is reasonable to ask providers how their facilities respond to voltage dips and whether ride-through requirements could change facility design or pricing.

    Background

    PJM Interconnection is a regional transmission organization, the independent body that runs the high-voltage grid and wholesale electricity market for an area stretching from New Jersey to Illinois. It serves 67 million customers and is the largest grid operator in the United States. Its territory includes Northern Virginia, which has the highest concentration of data centers in the world.

    Data centers are built never to lose power. When grid voltage wavers, they switch to on-site backup, such as uninterruptible power supplies and generators, in a split second. That design protects the computers inside. When many facilities share the same stretch of grid, however, it also means they can react to the same disturbance at the same moment. PJM saw this in 2024, when 60 data centers disconnected simultaneously, and saw it again at twice the scale this July. ERCOT, the operator of most of Texas’s grid, is among the grid managers moving to require large loads to ride through disturbances.

    Sources

    Source: One fallen power line exposed a growing AI data center problem — here’s how to fix it (TechCrunch): a report on the roughly 3-gigawatt data center disconnection on the PJM grid and proposed ride-through fixes.

  • 70% Oppose AI Data Centers Nearby. Their Power Lines Hinge on In-State Benefit

    70% Oppose AI Data Centers Nearby. Their Power Lines Hinge on In-State Benefit

    TL;DR · 30-second read

    The Short Version

    Power companies building electricity lines to feed new data centers, the warehouses of computers that run tools like ChatGPT, are using the government’s power to force landowners to sell.

    That power is only supposed to be used when the public benefits. Courts have usually allowed it when a line makes local electricity more dependable. One state’s top court blocked a line that crossed the state without serving anyone who lived there.

    With 7 in 10 Americans against data centers near them, expect more fights over farms and backyards.

    Power companies in states including Georgia and Pennsylvania have turned to eminent domain, the government power to take private property without the owner’s consent, to secure land for transmission lines serving the data center buildout. The practice is drawing opposition as polling shows 7 in 10 Americans oppose AI data centers in their own communities, University of Dayton law professor Aaron Walayat wrote in an essay published by The Conversation and republished by Fortune on July 19, 2026.

    The United States has more than 3,000 data centers, with another 1,500 in development, according to a Pew Research Center analysis. Data centers accounted for more than 4% of national electricity use in 2024. The legal question now in play is whether a line built to serve a private data center meets the Constitution’s “public use” requirement for taking land.

    Executive Summary

    Local opposition to data centers has mostly focused on the buildings themselves: utility bills, noise, pollution, water use and lost green space. It is now spreading to the transmission lines that carry power to those buildings. Transmission lines often have to cross private land, and when owners refuse to sell an easement, which is a right to use a strip of their property, utilities can ask a court to force the sale through condemnation.

    This matters because transmission is already one of the slowest parts of bringing new data center capacity online. A line that faces a credible legal challenge on public-use grounds adds legal risk to a project’s schedule. Precedent points to a consistent dividing line. Courts have upheld takings when a line delivers power or improves grid reliability for customers inside the state. They have been more skeptical when a line serves nobody in the state it crosses.

    For developers, utilities and regulators, how a line is justified in the record, and whom it demonstrably serves, is becoming as consequential as where it is routed.

    The Siting Fight Moves From the Building to the Wire

    A data center can be sited on a single parcel bought from a willing seller. The power it needs usually cannot. High-voltage transmission lines run for miles across many owners’ land, and every parcel on the route has to be secured. With more than 3,000 US data centers operating and another 1,500 in development, and with data centers already using more than 4% of the country’s electricity in 2024, utilities are planning new lines at a pace that makes holdout landowners a practical problem, not a rare one.

    The standard sequence is negotiation first and condemnation second. A utility offers to buy an easement. If the landowner declines, the utility, exercising power delegated by the state, asks a court to compel the sale at a court-determined “just compensation.” That is how power companies in Georgia and Pennsylvania have approached land acquisition for new lines. The 7-in-10 opposition figure measures attitudes toward data centers rather than transmission specifically, but the objections voters cite, higher bills and loss of green space, apply directly to a line crossing someone’s farm.

    Why In-State Benefit Is the Test That Decides These Cases

    The federal “public use” standard is permissive, so the contest shifts to state courts and state law, where a clear pattern emerges. The supreme courts of South Dakota and Vermont upheld utility takings because the lines provided at least some energy and improved grid reliability for in-state customers. In 1984, the Mississippi Supreme Court rejected a condemnation for a line that would have run from Mississippi into Louisiana without serving any Mississippi customers. In Texas, the state Supreme Court has held that a common carrier’s project must “serve the public” and “cannot be built only for the builder’s exclusive use.”

    Put together, those rulings describe the mechanism. A line documented as reinforcing reliability for a state’s own ratepayers fits well-established precedent, and the growing strain data centers place on the grid strengthens that case. A line whose practical function is to feed one private campus, or to carry power across a state border to load elsewhere, gives landowners a specific legal argument. Walayat’s reading is that reliability-driven takings will likely qualify as public use, while disputes over whether a line actually serves in-state customers remain the opening for challenges.

    The people most affected are the ones who write the justification. Utilities and their regulators decide how a line’s purpose is described in planning and certificate proceedings. Developers decide whether to take power from a dedicated feeder or from broader network upgrades. Landowners’ lawyers will look for evidence in that record that the public benefit is incidental. Projects that can show real benefit to in-state customers stand on firmer ground. Projects that cannot are carrying legal risk that belongs in their schedules.

    Kelo’s Long Shadow Makes State Lines Matter

    The backdrop is Kelo v. City of New London, the 2005 decision in which the US Supreme Court allowed a city to take homes for private redevelopment near a Pfizer facility on economic-development grounds. The redevelopment never happened, and Pfizer later left the city. The backlash was lasting: 45 states enacted eminent domain reform laws, and the supreme courts of Michigan, Ohio and Oklahoma have barred taking private property to hand it to another private party purely for economic development.

    For data center infrastructure, that history means a landowner’s odds depend heavily on the state. Challenges under a restrictive state constitution may succeed where a federal claim would not. Courts still routinely permit utilities to condemn land, so this is not a veto over transmission. It does mean that justifying a line as good for local economic growth, the argument Kelo accepted, is a weaker footing in many states than justifying it as necessary for reliable service to local customers.

    Weighing the Claims on Both Sides

    Each side’s argument deserves scrutiny. The industry’s position, that new lines are needed to keep the grid reliable as demand rises, is supported by the demand figures. It is also the same argument courts reward, which gives utilities an incentive to frame data center lines in reliability terms whether or not that is their main purpose. The opposition’s position, that private companies are borrowing a public power for private gain, echoes Kelo, where the promised public benefit never arrived. It has to be tested line by line, though, because many transmission projects do serve broad customer bases.

    The 70% figure is a strong signal of political headwind. It is not a legal standard. Public use is decided on the facts of each project, not by polling. The practical question for each contested line is the one courts have already asked: who in this state actually gets power from it?

    Background

    Eminent domain rests on the Fifth Amendment, which allows the government to take private property for public use if it pays just compensation. Most condemnations are carried out by state and local governments, which can delegate the power to utilities such as power and water companies. The US Supreme Court’s 2005 Kelo v. City of New London ruling read “public use” broadly to include economic development. The resulting backlash led 45 states to pass reform laws, and several state supreme courts, including those of Michigan, Ohio and Oklahoma, interpret their own constitutions more strictly.

    The AI boom has brought a matching surge in data center construction, to more than 3,000 facilities in operation and about 1,500 in development. Those facilities used more than 4% of US electricity in 2024, which pushes utilities to build new transmission. Those lines increasingly cross land whose owners do not want them.

    Sources

    Source: Power companies are using eminent domain to seize land for data centers as 70% of Americans say not in my backyard (Fortune, republished from The Conversation). An essay by University of Dayton law professor Aaron Walayat on the legal limits of taking land for data center transmission lines.

  • A 6,831 MW Shortfall at PJM’s $325 Cap Shows Data Center Power Is a Build Problem

    A 6,831 MW Shortfall at PJM’s $325 Cap Shows Data Center Power Is a Build Problem

    TL;DR · 30-second read

    The Short Version

    The organization that runs the electric grid for 67 million people across 13 states, including Pennsylvania, held its auction to line up power plants for 2028 and 2029. The price hit the maximum allowed, again. Even at that price, it could not secure as much power as it wanted.

    Data centers, giant buildings full of computers, are one big reason demand is climbing fast. A Pennsylvania consumer advocate says higher power costs already add $220 to $320 a year to a typical household’s bill. Paying top dollar is not fixing it, because new power plants cannot be built and connected fast enough.

    PJM Interconnection, the Valley Forge, Pennsylvania-based nonprofit that operates the largest electricity grid in the United States, announced on July 14, 2026 that its latest capacity auction cleared at $325 per megawatt-day for the 2028-2029 delivery year. That is the maximum allowed under a price cap first negotiated by Pennsylvania Governor Josh Shapiro’s administration after the 2024 auction set a record of $269.92, and later extended at the request of PJM-state governors and the Trump administration. The Pennsylvania Capital-Star reported that the auction also fell 6,831 megawatts short of PJM’s capacity goal, a larger deficit than in last year’s auction.

    PJM President and CEO David Mills said the results show “demand for electricity continues to grow faster than electricity supply.” PJM’s peak demand forecast has risen by 66,000 megawatts through 2036, driven by retiring fossil fuel plants, electrification of transportation and industry, and proposed data center development.

    Executive Summary

    PJM’s capacity auction, the mechanism it uses to pay power plants to be available on the hottest and coldest days of the year, hit its price ceiling again. At $325 per megawatt-day, the 13-state grid still came up 6,831 megawatts short of its target. The cap will also apply to the next auction, scheduled for December and covering 2030 and 2031.

    This matters beyond the price. When an auction clears at its maximum and still falls short, the shortfall shows how much supply the highest permitted price could not attract. Consumer advocates and the generators’ own trade association disagree on a lot, but both point to the same near-term obstacle: getting new plants built and connected to the grid. The main limit on power for data centers in the largest US grid is construction and interconnection, not willingness to pay.

    For households, the cost is already visible. Pennsylvania’s former consumer advocate estimates the last two auctions added about $16 billion in reliability costs, and $220 to $320 a year to the average Pennsylvania residential bill.

    At the Ceiling, the Price Signal Runs Out of Room

    A capacity auction is supposed to work like any market. If the grid needs more standby power, the price rises until enough generators commit to being available. The price is quoted per megawatt-day, the payment for one megawatt of capacity held ready for one day. In this auction that mechanism hit its limit. The clearing price of $325 is the cap itself, and even at that price PJM ended up 6,831 megawatts below its capacity goal, a wider gap than last year’s.

    This is the key point for anyone planning around PJM power. A market that clears below its cap tells you what supply costs. A market that clears at its cap and still comes up short only tells you that the maximum permitted price was not enough. Two years ago the record was $269.92. Prices are now pinned at the ceiling, and the ceiling has been extended through the December auction for 2030 and 2031. Patrick Cicero, the former Pennsylvania consumer advocate now with the Pennsylvania Utility Law Project, described what that looks like: “These are flat prices that are going to remain high. It’s not necessarily another spike, but it’s really, really high prices remaining.”

    Why the Constraint Is Construction, Not Capital

    Robert Routh of the Natural Resources Defense Council blames data center load for the price pressure, and Todd Snitchler of the Electric Power Supply Association, which represents competitive generators, defends the price as a healthy investment signal. The two still converge on where the bottleneck sits. Routh said a lack of money is not among the problems: “Tech companies, data center customers that have a need for power have deep pockets. Any power plant that can get built these days should have no problem finding buyers and arranging financing.” He named the real obstacles as supply chain delays, long construction timelines, and siting and permitting hurdles. Snitchler said “new supply is coming; the issue now is to address getting it connected to the system as quickly as possible.”

    That connection step is PJM’s responsibility. The grid operator vets proposed power plants and transmission lines before approving them to connect, and it has faced intense criticism for a years-long backlog of projects waiting in that line, often called the interconnection queue. Some projects dropped out while they waited. PJM says it has made significant progress by prioritizing shovel-ready projects.

    There is one honest caveat. Because the cap is binding, this auction cannot show how much supply an uncapped price might have drawn in, and EPSA’s argument that years of record-low prices discouraged investment deserves weight. Still, even the generators’ trade group names connection rather than compensation as the near-term limit. For data center developers, the implication is plain: a higher bid does not produce a megawatt that has not been built. The scarce resources are deliverable, connected capacity and the time it takes to create it.

    Who Carries the Cost, and the Proposal to Separate It

    The link between auction prices and retail bills is indirect, but it is real. Cicero said the last two auctions added about $16 billion to the cost of ensuring reliability. Some Pennsylvania utilities have raised default rates, the rate paid by customers who do not shop for an electricity supplier, by up to 20%. He put the added cost to the average Pennsylvania residential customer at $220 to $320 per year.

    The policy response under discussion is a separate auction, sought by PJM-state governors and the Trump administration, in which data centers and other large-load customers would buy long-term power commitments that fund new capacity. Routh described it as a matchmaking venue to build new supply “without raising prices for everyone else.” By his own account, though, that process faces the same supply chain, timeline and permitting hurdles as everything else. It could change who pays for new generation. On its own, it does not shorten the time it takes to build and connect that generation, which is what closes a 6,831-megawatt gap.

    Weighing the Competing Explanations

    Each camp’s framing captures part of the picture. NRDC’s Routh attributes the pressure to data centers directly: “Data center load growth is degrading grid reliability, and it’s raising prices to the Governor Shapiro-negotiated cap.” PJM’s 66,000-megawatt forecast increase through 2036, nearly 80 times the output of the Three Mile Island nuclear plant, bundles three drivers into one number: retiring fossil plants, electrification, and proposed data centers. How much of that number belongs to data centers is the question that decides whether large-load cost allocation addresses most of the problem or only part of it.

    The Three Mile Island example shows how the pieces fit together. That plant is set to reopen next year to serve data centers exclusively, a sign that large tech buyers are already securing dedicated supply outside the shared pool. Snitchler’s point that new supply is coming is plausible given that buying interest. Until it is connected, however, the region is running on the capped price and a growing shortfall, and the costs fall largely on customers who did not create the new load.

    Background

    PJM Interconnection coordinates electricity supply across 13 states, including Pennsylvania, for 67 million customers. Alongside real-time grid operations, it runs capacity auctions years in advance to ensure enough generators are on standby for peak demand. It also reviews and approves new power plants and transmission lines seeking to connect, a process that has drawn criticism for a years-long backlog.

    Capacity prices in PJM were low for years, which the generators’ trade association says discouraged investment. The 2024 auction broke that pattern with a record $269.92 per megawatt-day. Pennsylvania’s governor then negotiated a price cap, and PJM later extended it at the request of state governors and the Trump administration. Demand forecasts have risen sharply since, as fossil plants retire, transportation and industry electrify, and data center proposals multiply.

    Sources

    Source: PJM Interconnection electricity price hits cap again in latest auction (Pennsylvania Capital-Star): PJM’s 2028-2029 capacity auction clears at the $325 cap and falls 6,831 megawatts short of its goal.